NOx and CO control for gas turbine

Abstract

Method and apparatus for maintaining a substantially constant level of NO x and minimizing CO emissions from a gas turbine. The emission levels are maintained by injecting a calculated amount of steam into the combustion section of the gas turbine. The amount of steam injected is varied based on fuel flow, inlet air temperature, relative humidity, fuel heating value and turbine load which is a function of the turbine firing temperature.

We claim: 
     
       1. A system for automatically maintaining substantially constant NO x  emissions and minimum CO emissions from a gas turbine burning a gaseous or liquid fossil fuel injected into a combustor through at least one fuel input valve comprising: means for determining the actual fuel flow, W f , injected into the combustor;   a steam source;   a steam valve coupled between said steam source and said combustor for coupling a predetermined amount of steam, W s , into the combustor; and   means for automatically controlling the steam valve position to provide a steam flow, W s , that gives a steam-to-fuel ratio, SFR, that will maintain substantially constant nitrogen oxide emissions and minimal carbon monoxide emissions from the gas turbine according to the formula (W s  =SFR ×W f ) where W s  equals steam flow in pounds per hour, W f  equals fuel flow in pounds per hour and SFR equals the steam-to-fuel ratio corrected for variations in relative humidity, ambient temperature, fuel heating value, and turbine firing temperature.   
     
     
       2. A system as in claim 1 wherein the steam-to-fuel ratio is a straightline function with respect to turbine firing temperature, T 5 , according to the equation:   SFR=0.0011T.sub.5 -0.5325.     
     
     
       3. A system as in claim 2 further including: means for generating a first electrical signal representing W f  in pounds per hour as a function of the angular position of the fuel input valve;   means for generating a second electrical signal representing relative humidity in percent;   means for generating a third electrical signal representing a fuel heating value, HV, in BTU/SCF;   means for generating a fourth electrical signal representing ambient air temperature, T 2 , in degrees Fahrenheit;   means for generating a fifth electrical signal representing turbine load as a function of turbine firing temperature T 5  in degrees Fahrenheit; and   means for generating a sixth electrical signal representing steam flow, W s  in pounds per hour as a function of said steam valve position.   
     
     
       4. A system as in claim 3 including means to generate a corrected steam/fuel ratio, SFR, according to the equation:   SFR=(A+B)-E     where   A=a correction factor to the SFR for ambient air temperature T 2  ;   B=a correction factor to the SFR with changes in fuel heating value, HFV, corrected for ambient temperature T 2  and turbine firing temperature T 5  ; and   E=a correction factor to the SFR for humidity variations.   
     
     
       5. A system as in claim 4 wherein said means for generating the correction factor "A" further includes: means for multiplying the fifth electrical signal, T 5 , by the constant 0.0011 and subtracting 0.5325 from the result to obtain Y 1  ;   means for multiplying the fourth electrical signal, T 2 , by the constant 0.0003 to obtain Y 2  ; and   means for subtracting Y 2  from Y 1  according to the equation (A=Y 1  -Y 2 )=[0.0011T 5  -0.5325 ]-0.0003T 2 .   
     
     
       6. A system as in claim 5 wherein said means for generating the correction factor B further includes: means for generating a first correction value by modifying the second electrical signal, HV, with constants for a range of HV values according to the equations:   Y.sub.3 =-0.008333HV+7.084973 for 800<HV ≦825 BTU/SCF       Y.sub.3 =-0.042000HV+34.860000 for 825<HV ≦830 BTU/SCF       Y.sub.3 =+0.006561HV-5.445398 for 830<HV ≦896 BTU/SCF       Y.sub.3 =+0.003451HV-2.659000 for 896<HV ≦998 BTU/SCF       means for generating a second correction factor by multiplying the fourth electrical signal, T 2 , by a first constant and adding a second constant to the result according to the equations:   Y.sub.4 =0.001795T.sub.2 +0.894100 for T.sub.2 <59° and       Y.sub.4 =1 for T.sub.2 ≧59° ;       means for generating a third correction value by multiplying the fifth electrical signal, T 5 , by a first constant and subtracting a second constant from the result according the equation:   Y.sub.5 =0.00741T.sub.5 -0.092530; and       means for multiplying the first, second and third correction values together to obtain the correction factor "B" according to the equation:   B=Y.sub.3 ×Y.sub.4 ×Y.sub.5.       
     
     
       7. A system as in claim 6 wherein the correction factor, E, also includes correction factors C and D according to the equation:   E=(C+D)·RH/100     where C=Y 6  ×Y 7 , Y 6  equals a correction for SFR versus humidity variations (RH) as a function of ambient temperature T 2 , and Y 7  is a function of the turbine firing temperature, T 5 , and     D=Y.sub.8 ×Y.sub.9,     where Y 8  equals a correction for SFR versus fuel heating value as a function of humidity (RH) and Y 9  is a function of ambient temperature, T 2 .   
     
     
       8. A system as in claim 7 further comprising: means for generating a correction factor Y 6  by varying the fourth electrical signal, T 2 , with constants for a range of T 2  values according to the equations: ##EQU6## means for generating the correction factor, Y 7 , by multiplying the fifth electrical signal T 5  by a constant 0.00047 and adding the constant 0.307 to the result according to the equation:   Y.sub.7 -0.00047T.sub.5 +0.307; and       means for multiplying the signals Y 6  and Y 7  to obtain   C=Y.sub.6 ×Y.sub.7.       
     
     
       9. A system as in claim 8 further including: means for generating the correction factor, Y 8 . by varying the third electrical signal with constants for a range of HV values according to the equations: ##EQU7## means for generating the correction factor, Y 9 , by varying the fourth electrical signal T 2  with constants for a range of T 2  values according to the equations: ##EQU8## means for multiplying Y 8  and Y 9  to obtain   D=Y.sub.8 ×Y.sub.9.       
     
     
       10. A system as in claim 9 wherein the means for generating the correction factor E comprises: means for adding C+D,   means for dividing the second electrical signal, RH, by 100 to obtain a value representing relative humidity in percent; and   means for multiplying the sum of C+D by the divided second electrical signal, RH/100, to obtain the correction factor E for relative humidity.   
     
     
       11. A system as in claim 10 further including: means for adding (A+B); and   means for subtracting E from said (A+B) to obtain   SFR=(A+B)-E.       
     
     
       12. A system as in claim 11 further comprising means for multiplying (A+B)-E=SFR by the first electrical signal, W f , to obtain the sixth electrical signal, W s . 
     
     
       13. A system as in claim 12 further comprising: means for coupling said sixth electrical signal, W s , to said steam valve for positioning said steam valve to allow sufficient steam to said combustor to satisfy the equation:   W.sub.s =SFR×W.sub.f     thereby maintaining substantially constant NO x  emissions and minimizing CO emissions from said turbine.     
     
     
       14. A method for automatically maintaining substantially constant nitrogen oxide and minimizing CO emissions from a gas turbine burning a gaseous or liquid fossil fuel injected into a combustor through at least one fuel input valve comprising the steps of: determining the actual fuel flow, W f , injected into the combustor;   providing a steam source;   coupling a steam valve between the steam source and the combustor for providing a predetermined amount of steam, W s , into the combustor; and   automatically controlling the steam valve to provide a steam flow, W s , that provides a steam-to-fuel ratio, SFR, that will maintain substantially constant nitrogen oxide and carbon monoxide emissions from the gas turbine according to the formula:   W.sub.s =SFR×W.sub.f     where W s  equals steam flow in pounds per hour, W f  equals fuel flow in pounds per hour and SFR equals the steam-to-fuel ratio corrected for variations in relative humidity, ambient temperature, fuel heating value, and turbine firing temperature.     
     
     
       15. A method as in claim 14 further comprising the step of relating the turbine firing temperature, T 5 , to the turbine load as a straightline function according to the equation:   SFR=0.0011T.sub.5 -0.5325.     
     
     
       16. A method as in claim 15 further including the steps of: generating a first electrical signal representing W f  in pounds per hour as a function of the angular position of the fuel input valve;   generating a second electrical signal representing relative humidity, RH, in percent;   generating a third electrical signal representing fuel heating value, HV, in BTU/SCF;   generating a fourth electrical signal representing ambient air temperature, T 2 , in degrees Fahrenheit;   generating a fifth electrical signal representing turbine load as a function of turbine firing temperature, T 5 , in degrees Fahrenheit; and   generating a sixth-electrical signal representing steam flow, W s , in pounds per hour as a function of said steam valve position.   
     
     
       17. A method as in claim 16 including the step of generating a corrected SFR according to the equation:   SFR=(A+B)-E     where   A=a correction factor to the SFR for ambient temperature, T 2  ;   B=a correction factor to the SFR for changes in fuel heating value, FHV, corrected for ambient temperature T 2  and turbine firing temperature T 5  ; and   E=a correction factor for relative humidity variations, RH.   
     
     
       18. A method as in claim 17 wherein the step of generating the correction factor A further includes the steps of: multiplying the fifth electrical signal, T 5 , by the constant 0.0011 and subtracting 0.5325 from the result to obtain Y 1  ;   multiplying the fourth electrical signal, T 2 , by the constant 0.0003 to obtain Y 2  ; and   subtracting Y 2  from Y 1  according to the equation: ##EQU9##   
     
     
       19. A method as in claim 18 wherein the step of generating the correction factor B further includes the steps of: generating a first correction value by modifying the second electric signal, HV, with constants for a range of HV values according to the equations: ##EQU10## means for generating a second correction value by multiplying the fourth electrical signal, T 2 , by a first constant and adding a second constant to the result according to the equations:   Y.sub.4 =0.001795T.sub.2 +0.894100 for T.sub.2 <59° and       Y.sub.4 =1 for T.sub.2 ≧59° ;       generating a third correction value by multiplying the fifth electrical signal, T 5 , by a first constant and subtracting a second constant from the result according to the equation:   Y.sub.5 =0.000741T.sub.5 -0.092530; and       multiplying the first, second and third correction values together to obtain the correction factor, B, according to the equation:   B=Y.sub.3 ×Y.sub.4 ×Y.sub.5.       
     
     
       20. A method as in claim 19 further including the step of adding correction factors C and D to obtain the correction factor E according to the equation:   E=(C+D)·RH/100     where C equals Y 6  ×Y 7 ,Y 6  is a correction for SFR versus humidity variations (RH) as a function of ambient temperature T 2  and Y 7  is a function of turbine firing temperature T 5  and     D=Y.sub.8 ×Y.sub.9     where Y 8  equals a correction for SFR versus fuel heating values as a function of humidity (RH) and Y 9  is a function of ambient temperature T 2 .   
     
     
       21. A method as in claim 20 further comprising the steps of: generating a correction factor, Y 6 , by varying the fourth electrical signal, T 2 , with constants for a range of T 2  values according to the equations: ##EQU11## generating the correction factor, Y 7 , by multiplying the fifth electrical signal, T 5 , by a constant 0.00047 and adding the constant to 0.307 to the result according to the equation:   Y.sub.7 =0.00047T.sub.2 +0.307; and       multiplying the signals Y 6  and Y 7  to obtain   C=Y.sub.6 ×Y.sub.7.       
     
     
       22. A method as in claim 21 further including the steps of: generating the correction factor, Y 8 , by varying the third electrical signal with constants for a range of HV values according to the equations: ##EQU12## generating the correction factor Y 9  by varying the fourth electrical signal T 2  with constants for a range of T 2  values according to the equations:   Y.sub.9 =0.003220T.sub.2 +0.050000 for T.sub.2 ≦67.4° F.       Y.sub.9 =0.022500T.sub.2 -1.250000 for 67.4° F. <T.sub.2 ≦100° F.; and       multiplying Y 8  and Y 9  to obtain   D=Y.sub.8 ×Y.sub.9.       
     
     
       23. A method as in claim 22 wherein the step of generating the correction factor E further comprises the steps of: adding C+D;   dividing the second electrical signal, RH, by 100 to obtain a value representing relative humidity in percent; and   multiplying the sum of C+D by the divided second electrical signal, RH/100 to obtain the correction factor E for relative humidity.   
     
     
       24. A method as in claim 23 further including the steps of: adding A+B; and   subtracting E from the quantity (A+B) to obtain   SFR=(A+B)-E.       
     
     
       25. A method as in claim 24 further comprising the step of multiplying (A+B)-E=SFR by the first electrical signal, W f , to obtain the sixth electrical signal, W s , according to the equation:   W.sub.s =SFR×W.sub.f.     
     
     
       26. A method as in claim 25 further comprising the step of coupling the sixth electrical signal, W s , to the steam valve for positioning the steam valve to allow sufficient steam to said combustor to satisfy the equation:   W.sub.s =SFR×W.sub.f.     thereby minimizing NO x  and CO emissions from said turbine.